Recently, as one of the causes of global warming, a greenhouse effect due to CO2 has been pointed out, and a measure against it becomes urgent internationally for protecting the global environment. Generation sources of CO2 include all sorts of human activities that burn fossil fuel, and demands for reducing discharges thereof are increasing further. Accompanying this demand, a method of removing and recovering CO2 in combustion discharge gas by bringing combustion discharge gas in a boiler into contact with an amine CO2 absorbent (hereinafter, also “absorbent”), and a method of storing recovered CO2 without discharging it to the air have been strenuously researched, with regard to power generation facilities such as a thermal power plant that uses a large amount of fossil fuel.
There has been disclosed a method in which, after CO2 is removed by absorption from discharge gas by using an absorbent, CO2 is diffused and recovered, and the absorbent is regenerated, circulated in a CO2 absorber again, and reused (see, for example, Patent document 1).
FIG. 4 is a configuration example of a conventional CO2 recovery unit. As shown in FIG. 4, a conventional CO2 recovery unit 100 includes a CO2 absorber 13 that removes CO2 in flue gas 11 by bringing the flue gas 11 containing CO2 discharged from industrial combustion facilities such as a boiler and a gas turbine into contact with a CO2 absorbent 12 that absorbs CO2, and a regenerator 15 that diffuses CO2 from a CO2 absorbent 14 having absorbed CO2 (hereinafter, also “rich solution”) to regenerate the CO2 absorbent 12.
In the CO2 recovery unit 100, CO2 is diffused in the regenerator 15, and the regenerated CO2 absorbent 12 (hereinafter, also “lean solution”) is reused as the CO2 absorbent in the CO2 absorber 13. CO2 gas 16 recovered in the regenerator 15 is compressed by a compressor, injected into an oilfield, and used for enhanced oil recovery (EOR), accumulated in a water-bearing layer as a measure against global warming, or used as a synthetic raw material of chemical products.
In FIG. 4, reference numeral 17 denotes flue gas in which CO2 is removed in the CO2 absorber 13, 18 denotes a rich solvent pump that feeds the rich solution 14 to the regenerator 15, 19 denotes rich/lean solvent heat exchanger that performs heat exchange between the rich solution 14 and the lean solution 12, 20 denotes a lean solvent pump that feeds the lean solution 12 to the CO2 absorber 13, 21 denotes a lean solvent cooler that cools the lean solution 12, 22 denotes a regenerating heater, and 23 denotes water vapor.
FIG. 5 is an example of a process of injecting the CO2 gas 16 recovered in the regenerator 15 into the ground. The pressure of the CO2 gas 16 recovered in the regenerator 15 is raised at a compressing process 101, and transported to a well 103a at an accumulation point by a transport unit 102 such as a pipeline or a ship. In the well 103b at the accumulation point, for example, gas (hereinafter, also “recycle gas”) accompanying crude oil is mixed with gas 105 refined in a recycle-gas purification facility 104, and injected into the ground 107 at an injecting process 106. At this time, if hydrogen sulfide (H2S) is contained in recycle gas 105, as shown in equation below, oxygen (O2) contained in the CO2 gas 16 reacts with H2S to precipitate solid sulfur (S), and operation of a plant can be affected.2H2S+O2=2S+2H2O  (1)
Further, when moisture remaining in the CO2 gas 16 is condensed due to compression, carbonic acid corrosion may be promoted due to coexistence of oxygen. As another method of preventing precipitation of sulfur, a method of supplying N2 gas at the time of start-up and shut-down of a compressor to remove sulfur contents (S contents) and O2 remaining in the compressor and piping has been adopted (see, for example, Nonpatent literature 1).
Further, because carbonic acid corrosion can be caused when moisture remaining in the CO2 gas 16 is condensed due to compression, there has been adopted a method such that CO2 gas is brought into contact with a dehydrating agent such as a molecular sieve, diethylene glycol (DEG), or triethylene glycol (TEG) to reduce moisture contained in CO2 gas, thereby preventing carbonic acid corrosion.
FIG. 6 depicts a process of compressing CO2 gas recovered in a regenerator. As shown in FIG. 6, the CO2 gas 16 accompanied with water vapor released from the rich solution 14 and semi-lean solution in the regenerator is derived from a top part of the regenerator 15 via a gas discharge line 25, water vapor is condensed by a condenser 26, and water 28 is separated in a separation drum 27. The CO2 gas 16 accompanied with water vapor is compressed by a first compressor 29-1 to a fourth compressor 29-4, while gradually raising the pressure, and recovered as compressed CO2.
On a downstream side of each of the first to fourth compressors 29-1 to 29-4, a first cooler 30-1 to a fourth cooler 30-4 and a first separator 31-1 to a fourth separator 31-4 are respectively provided to reduce fluid generated by compressing the CO2 gas 16. A dehydrating column 33 is provided between the third compressor 29-3 and the fourth compressor 29-4, so that the CO2 gas 16 is brought into contact with a dehydrating agent 32 (molecular sieve or DEG or TEG) to reduce moisture in the CO2 gas 16, and is dehydrated.
In FIG. 6, reference numeral 34 denotes a gas-liquid separator, and 35 denotes a condensed-water circulating pump that supplies the water 28 separated in the separation drum 27 to an upper part of the regenerator 15.
Further, there has been adopted an apparatus in which a mist catcher is provided in a dehydrating column, so that a dehydrating agent (such as DEG or TEG) supplied to the dehydrating column is captured so as not to be fed to the downstream side of the dehydrating column accompanying CO2 gas (see, for example, Nonpatent literature 2).